Many hydrocarbon wells are unable to produce at commercially viable levels without assistance in lifting the formation fluids to the earth's surface. In some instances, high fluid viscosity inhibits fluid flow to the surface. More commonly, formation pressure is inadequate to drive fluids upward in the wellbore. In the case of deeper wells, extraordinary hydrostatic head acts downwardly against the formation and inhibits the unassisted flow of production fluid to the surface.
A common approach for urging production fluids to the surface uses a mechanically actuated, positive displacement pump. Reciprocal movement of a string of sucker rods induces reciprocal movement of the pump for lifting production fluid to the surface. For example, a reciprocating rod lift system 20 of the prior art is shown in FIG. 1A to produce production fluid from a wellbore 10. As is typical, surface casing 12 hangs from the surface and has a liner casing 14 hung therefrom by a liner hanger 16. Production fluid F from the formation 19 outside the cement 18 can enter the liner 14 through perforations 15. To convey the fluid, production tubing 30 extends from a wellhead 32 downhole, and a packer 36 seals the annulus between the production tubing 30 and the liner 14. At the surface, the wellhead 32 receives production fluid and diverts it to a flow line 34.
The production fluid F may not produce naturally reach the surface so operators use the reciprocating rod lift system 20 to lift the fluid F. The system 20 has a surface pumping unit 22, a rod string 24, and a downhole rod pump 50. The surface pumping unit 22 reciprocates the rod string 24, and the reciprocating string 24 operates the downhole rod pump 50. The rod pump 50 has internal components attached to the rod string 24 and has external components positioned in a pump-seating nipple 38 near the producing zone and the perforations 15.
As best shown in the detail of FIG. 1B, the rod pump 50 has a barrel 60 with a plunger 80 movably disposed therein. The barrel 60 has a standing valve 70, and the plunger 80 is attached to the rod string 24 and has a traveling valve 90. For example, the traveling valve 90 is a check valve (i.e., one-way valve) having a ball 92 and seat 94. For its part, the standing 70 disposed in the barrel 60 is also a check valve having a ball 72 and seat 74.
As the surface pumping unit 22 in FIG. 1A reciprocates, the rod string 24 reciprocates in the production tubing 30 and moves the plunger 80. The plunger 80 moves the traveling valve 90 in reciprocating upstrokes and downstroke. During an upstroke, the traveling valve 90 as shown in FIG. 1B is closed (i.e., the upper ball 92 seats on upper seat 94). Movement of the closed traveling valve 90 upward reduces the static pressure within the pump chamber 62 (the volume between the standing valve 70 and the traveling valve 90 that serves as a path of fluid transfer during the pumping operation). This, in turn, causes the standing valve 70 to unseat so that the lower ball 72 lifts off the lower seat 74. Production fluid F is then drawn upward into the chamber 62.
On the following downstroke, the standing valve 70 closes as the standing ball 72 seats upon the lower seat 74. At the same time, the traveling valve 90 opens so fluids previously residing in the chamber 62 can pass through the valve 90 and into the plunger 80. Ultimately, the produced fluid F is delivered by positive displacement of the plunger 80, out passages 61 in the barrel 60. The moved fluid then moves up the wellbore 10 through the tubing 30 as shown in FIG. 1A. The upstroke and down stroke cycles are repeated, causing fluids to be lifted upward through the wellbore 10 and ultimately to the earth's surface.
The conventional rod pump 50 holds pressure during a pumping cycle by using sliding mechanical and/or hydrodynamic seals disposed between the plunger's outside diameter and the barrel's inside diameter. Sand in production fluids and during frac flowback can damage the seals. In particular, the differential pressure across the seals causes fluid to migrate past the seals. When this migrating fluid contains sand, the seals can become abraded by the sand so the seals eventually become less capable of holding pressure. Overtime, significant amounts of sand can collect between the plunger and the barrel, causing the plunger to become stuck within the barrel.
Production operations typically avoid using such a rod pump in wellbores having sandy fluids due to the damage that can result. However, rod pumping in sandy fluids has been a goal of producers and lift equipment suppliers for some time. To prevent sand damage, screens can be disposed downhole from the pump 50 to keep sand from entering the pump 50 altogether. Yet, in some applications, using a screen in such a location may not be feasible, and the screen and the rathole below can become fouled with sand. In other applications, it may actually be desirable to produce the sand to the surface instead of keeping it out of the pump 50.
In addition to having sand or other solids, well fluids may also have a high volume of gas entrained therein. As noted above, pumping sandy fluid using a conventional pump causes premature plunger and barrel wear that decreases efficiency. For its part, pumping a gassy fluid decreases efficiency, can damage the pump and the rod string from fluid pounding, and can potentially lead to gas lock of the pump. Gas lock refers to the situation in which gas received into the subsurface pump 50 is alternately expanded and compressed in the pump 50 as the traveling valve 90 reciprocates, but fluid cannot flow into or out of the subsurface pump 50 due to the gas therein. Gas lock can result from gas being entrained in the fluid or can result from a pump-off condition (in which a liquid-gas interface in the well descends to below the stationary valve 70) so that the pump 50 will eventually no longer be able to pump a liquid component of the fluid.
Gas anchors have been used to address the issues with pumping of gassy fluid. Various types of gas anchors can be used, such as a natural gas anchor, a packer-type gas anchor, a poor boy gas anchor, and the like. In general, the gas anchor operates as a separator so that gas in well can be produced up the casing, while oil in the produced fluid enters the pump to be produced up the tubing disposed in the casing. The gas anchor can use features, such as tubing-intake perforations on the pump, a spill-over tube, a mud anchor with tubing-intake perforations, and a mud anchor with tubing-intake perforations and suction tube. A number of wells have casing and tubing dimensions that does not leave enough annulus for gas anchors to operate effectively.
According, a need exist for a subsurface pump capable of effectively handling high volumes of both solids and gas entrained in the well fluid. The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.